Methods for formulating a cement slurry for use in a subterranean salt formation

ABSTRACT

Methods of formulating a cement slurry for use in a subterranean salt formation, including methods for formulating a cement slurry capable of providing long-term zonal isolation within a subterranean salt formation. The methods also take into account the effects of treatment fluids on the cement slurry, such as drilling fluids, spacer fluids, flush fluids, or other relevant fluids used to perform a subterranean formation operation.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation of U.S. application Ser. No.14/429,919, filed Mar. 20, 2015, which is the national stage of entry ofInternational Patent Application No. PCT/US2014/040245, filed on May 30,2014, all of which are hereby incorporated by reference in theirentirety for all purposes.

BACKGROUND

The embodiments herein relate to methods for formulating a cement slurryfor use in a subterranean salt formation, and, more particularly, tomethods for formulating a cement slurry capable of providing long-termzonal isolation within a subterranean salt formation.

Subterranean formation operations (e.g., stimulation operations, sandcontrol operations, completion operations, etc.) often involve drillinga wellbore in a subterranean formation with a drilling fluid (andthereafter placing a cement sheath between the formation and a casing(or liner string) in the wellbore. The cement sheath is formed bypumping a cement slurry through the bottom of the casing and out throughan annulus between the outer casing wall and the formation face of thewellbore. The cement slurry then cures in the annular space, therebyforming a sheath of hardened cement that, inter alia, supports andpositions the casing in the wellbore and bonds the exterior surface ofthe casing to the subterranean formation. This process is referred to as“primary cementing.” Among other things, the cement sheath may keepfresh water reservoirs from becoming contaminated with produced fluidsfrom within the wellbore. As used herein, the term “fluid” refers toliquid phase fluids and gas phase fluids. The cement sheath may alsoprevent unstable formations from caving in, thereby reducing the chanceof a casing collapse and/or stuck drill pipe. Finally, the cement sheathforms a solid barrier to prevent fluid loss or contamination ofproduction zones. The degree of success of a subterranean formationoperation involving placement of a cement sheath, therefore, depends, atleast in part, upon the successful cementing of the wellbore casing andthe cement's ability to maintain zonal isolation of the wellbore.

Subterranean salt formations are often rich in hydrocarbons or otherdesirable fluids for production to the surface. As used herein, the term“subterranean salt formation” refers to a rock formation composedsubstantially (i.e., largely but not necessarily wholly) of salt. Avariety of salts may be found in a salt formation including, but notlimited to, halite, sylvite, bichofite, carnalite, polyhalite,tachydrite, anhydrite, and any combination thereof. However, drillingand cementing in such salt formations may be problematic due to saltcreep, for example. As used herein, the term “salt creep” refers to thephenomenon of salt in a formation under stress to deform significantlyas a function of time, depending on the loading conditions, and itsphysical properties, which permits the salt to flow into the wellboreand replace the volume of formation removed by the drill bit. Suchreplacement may reduce the size of the wellbore and/or may cause thedrill pipe to stick and eventually force abandonment of the well.Additionally, during drilling, a drilling fluid may be circulated to andfrom a wellbore and salt from the formation may become dissolved in thedrilling fluid, resulting in, among other things, wellbore opening(i.e., an increase in the radius/diameter of the wellbore), changes inthe rheology of the drilling fluid, and the like.

During cementing, the cement slurry may interact with and dissolve atleast a portion of the salts in the salt formation, thereby affectingthe hydration properties and final cured properties of a cement slurry.For example, dissolution of salt in the cement slurry may influence suchcement properties as, without limitation, free fluid, thickening time,compressive strength, rheological properties, and the like. In somecases, the influence of the salt dissolution by changing the geometry ofthe wellbore and the cement slurry properties may be particularlydetrimental and may result in the failure of zonal isolation in awellbore (e.g., by reducing the wellbore radius and through fluidinvasion or other loss of structural integrity to the hydrating or curedcement). Failure of zonal isolation, among other things, may result inenvironmental contamination, which may cause harm to both flora andfauna, including humans. Such failure may further prevent production orreduce the production capability of a wellbore, which may result inabandonment of the wellbore or costly and time-consuming remedialactions.

BRIEF DESCRIPTION OF THE DRAWINGS

The following FIGURES are included to illustrate certain aspects of theembodiments, and should not be viewed as exclusive embodiments. Thesubject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIG. 1 depicts an embodiment of a system configured for delivering thefinal cement slurries of one or more embodiments described herein to adownhole location.

DETAILED DESCRIPTION

The embodiments herein relate to methods for formulating a cement slurryfor use in a subterranean salt formation, and, more particularly, tomethods for formulating a cement slurry capable of providing long-termzonal isolation within a subterranean salt formation.

The methods described in the embodiments of the present disclosurepermit an operator to determine whether a particular cement slurryformulation may be used in a particular subterranean salt formation toform a cement sheath. The methods described herein may further take intoaccount specific job design, such as pumping time and pressurerequirements, prior to introducing the cement slurry in the formation.Accordingly, based on the results of the determination, the cementslurry may be manipulated one or more times and re-evaluated to ensurethat it is appropriate for the particular subterranean salt formation.Once an adequate cement slurry has been designed for use in thesubterranean salt formation, the cementing operation may be performedwith knowledge that the cement slurry will provide long-term zonalisolation. In some instances, other parameters, such as the drillingfluid, spacer fluid, flush fluid, or other relevant fluids used toperform a subterranean formation operation, or the duration of time thetreatment fluid is used (e.g., drilling time), may be manipulated, aswell as the cement slurry, or may be manipulated without manipulatingthe cement slurry, prior to introducing the cement slurry into thewellbore.

One or more illustrative embodiments disclosed herein are presentedbelow. Not all features of an actual implementation are described orshown in this application for the sake of clarity. It is understood thatin the development of an actual embodiment incorporating the embodimentsdisclosed herein, numerous implementation-specific decisions must bemade to achieve the developer's goals, such as compliance withsystem-related, lithology-related, business-related, government-related,and other constraints, which vary by implementation and from time totime. While a developer's efforts might be complex and time-consuming,such efforts would be, nevertheless, a routine undertaking for those ofordinary skill the art having benefit of this disclosure.

It should be noted that when “about” is provided herein at the beginningof a numerical list, the term modifies each number of the numericallist. In some numerical listings of ranges, some lower limits listed maybe greater than some upper limits listed. One skilled in the art willrecognize that the selected subset will require the selection of anupper limit in excess of the selected lower limit. Unless otherwiseindicated, all numbers expressing quantities of ingredients, propertiessuch as molecular weight, reaction conditions, and so forth used in thepresent specification and associated claims are to be understood asbeing modified in all instances by the term “about.” Accordingly, unlessindicated to the contrary, the numerical parameters set forth in thefollowing specification and attached claims are approximations that mayvary depending upon the desired properties sought to be obtained by theexemplary embodiments described herein. At the very least, and not as anattempt to limit the application of the doctrine of equivalents to thescope of the claim, each numerical parameter should at least beconstrued in light of the number of reported significant digits and byapplying ordinary rounding techniques.

While compositions and methods are described herein in terms of“comprising” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. When “comprising” is used in a claim, it is open-ended.

In some embodiments, a method is provided herein including calculating atheoretical first wellbore radius in a subterranean salt formation thatwould form as a result of using a treatment fluid in the formation. Asused herein, the term “formation-treatment fluid” refers to a wellborein a formation having a treatment fluid therein, or a modeled versionthereof (e.g., for use in modeling fluids in the actual formation). Thetreatment fluid may be a drilling fluid, a pad fluid, a spacer fluid, aflush fluid, an acidizing fluid, and the like. The treatment fluid maybe a Newtonian or a non-Newtonian fluid, without departing from thescope of the present disclosure. The theoretical first wellbore radiusis determined based on salt creep analysis of the wellbore in thepresence of formation-treatment fluid, taking into account the actualparameters and composition of the proposed salt formation and thedensity of the treatment fluid and formation. The analysis may use afinite element technique or any other numerical solution technique oranalytical/semi-analytical technique capable of solving the salt creepmodel equations along with constitutive relations for solid structures.As described herein, the methods of the present disclosure may bedescribed with reference to the treatment fluid being a drilling fluid,but any such other treatment fluids used for other operations may beevaluated using the methods of the present disclosure.

The treatment fluid may be any fluid capable of use in the subterraneansalt formation for performing an operation therein. In some embodiments,the treatment fluid may comprise a base fluid selected from the groupconsisting of an oil base fluid, an aqueous base fluid, anaqueous-miscible base fluid, a water-in-oil emulsion base fluid, anoil-in-water emulsion base fluid, and any combination thereof. Suitableoil base fluids may include, but are not limited to, alkanes, olefins,aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids,mineral oils, desulfurized hydrogenated kerosenes, and any combinationthereof. Suitable aqueous base fluids may include, but are not limitedto, fresh water, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated salt water), seawater, andany combination thereof. Suitable aqueous-miscible base fluid mayinclude, but are not limited to, alcohols (e.g., methanol, ethanol,n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol, andt-butanol), glycerins, glycols (e.g., polyglycols, propylene glycol, andethylene glycol), polyglycol amines, polyols, any derivative thereof,any in combination with salts (e.g., sodium chloride, calcium chloride,calcium bromide, zinc bromide, potassium carbonate, sodium formate,potassium formate, cesium formate, sodium acetate, potassium acetate,calcium acetate, ammonium acetate, ammonium chloride, ammonium bromide,sodium nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate,calcium nitrate, sodium carbonate, and potassium carbonate), any incombination with an aqueous base fluid, and any combination thereof.Suitable water-in-oil emulsion base fluids, also known as invertemulsions, may have an oil-to-water ratio from a lower limit of greaterthan about 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to anupper limit of less than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25,70:30, or 65:35 by volume in the base fluid, where the amount may rangefrom any lower limit to any upper limit and encompass any subsettherebetween. It should be noted that for water-in-oil and oil-in-wateremulsion base fluids, any mixture of the above may be used including thewater being and/or comprising an aqueous-miscible base fluid. Generally,the base fluid may be from any source provided, for example, that itdoes not contain an excess of compounds that may undesirably affect theperformance of the treatment fluid, such as being able to drill with iteconomically, fracture with it, suspend and remove drill cuttings, andthe like.

In addition to the base fluid, the treatment fluid may additionallycomprise one or more additives. Suitable additives may include, but arenot limited to, a salt, a weighting agent, an inert solid, a fluid losscontrol agent, an emulsifier, a dispersion aid, a corrosion inhibitor,an emulsion thinner, an emulsion thickener, a viscosifying agent, agelling agent, a surfactant, a particulate, a proppant, a gravelparticulate, a lost circulation material, a foaming agent, a gas, a pHcontrol additive, a breaker, a biocide, a crosslinker, a stabilizer, achelating agent, a scale inhibitor, a gas hydrate inhibitor, a mutualsolvent, an oxidizer, a reducer, a friction reducer, a clay stabilizingagent, and any combination thereof.

A theoretical second wellbore radius is calculated next during acementing operation using a proposed cement slurry, the theoreticalsecond wellbore radius is also calculated based on salt creep analysisof the wellbore in the presence of the formation-cement slurry after thetreatment fluid has been used in the formation, taking into account theactual parameters and composition of the proposed salt formation afteruse of the treatment fluid and the density of the cement slurry andformation. As used herein, the term “formation-cement slurry” refers toa wellbore in a formation having a liquid (i.e., not fully set) cementslurry therein, or a modeled version thereof (e.g., for use in modelingthe cement slurry in the actual formation). The analysis may use afinite element technique or any other numerical solution technique oranalytical/semi-analytical technique capable of solving the salt creepmodel equations along with constitutive relations for solid structures.As mentioned above, the wellbore may initially be the size of, forexample, the drill bit used to form the wellbore in the salt formation.However, after time due to salt creep, at a point between the initialdrilling of the formation and a cementing operation (prior to settingthe cement or during “hydration”), the radius of the wellbore maydecrease due to salt deformation and deposition on the formation wallsduring both the drilling phase, any other treatment phase, and thecementing phase. Accordingly, a shrinkage or closure of the wellbore mayoccur and is taken into account using the methods of the presentdisclosure. This procedure may also be extended to other fluids used inthe wellbore such as, for example, circulating mud, spacer, and flushfluids that may be pumped into the wellbore before the cement slurry.

The proposed clement slurry may be used during an actual cementingoperation after the proposed cement slurry has been optimized for theparticular subterranean salt formation and job parameters using themethods described herein; that is, after a final cement slurrycomposition has been determined. As used herein, the term “cementslurry” may be collectively used to refer to both the proposed cementslurry and the final cement slurry of the present disclosure. Thecementing operation, as described above, involves forming a cementsheath capable of withstanding a wellbore load to prevent failure of thecement sheath in the wellbore. As used herein, the term“formation-cement sheath” refers to a wellbore in a formation having acement sheath therein (e.g., a casing that has been cemented using acement sheath), or a modeled version thereof (e.g., for use in a cementsheath in the actual formation). The wellbore load may be calculatedbased on the particulars of the salt formation, the geometry of thewellbore, and the like. Typically, the wellbore load must be withstoodby the cement sheath so that failure of zonal isolation does not occur.During the experimental portion of the methods described herein, thecement sheath may be referred to as a proposed cement sheath.

In some embodiments, the cement slurry may comprise an aqueous basefluid and a cementitious material. Any aqueous base fluid suitable foruse in forming a curable cerement slurry capable of use in asubterranean salt formation may be suitable for use in the embodimentsdescribed herein. In particular, the suitable aqueous base fluids foruse in the proposed and final cement slurries discussed herein may beany aqueous base fluid suitable for use in the subterranean formation,as previously discussed, including, but not limited to, freshwater,saltwater, brine, seawater, and any combination thereof. Generally, theaqueous base fluid may be from any source provided, for example, that itdoes not contain an excess of compounds that may undesirably affect theperformance of the proposed or final cement slurry or the pumpabilitythereof.

The cementitious material of the embodiments herein may be anycementitious material suitable for use in forming a curable cementslurry. In preferred embodiments, the cementitious material may be ahydraulic cement. Hydraulic cements harden by the process of hydrationdue to chemical reactions to produce insoluble hydrates (e.g., calciumhydroxide) that occur independent of the cement's water content (e.g.,hydraulic cements can harden even under constantly damp conditions).Thus, hydraulic cements are preferred because they are capable ofhardening regardless of the water content of a particular subterraneanformation. Suitable hydraulic cements may include, but are not limitedto Portland cement, Portland cement blends (e.g., Portland blast-furnaceslag cement and/or expansive cement), non-Portland hydraulic cement(e.g., super-sulfated cement, calcium aluminate cement, and/or highmagnesium-content cement), and any combination thereof. Generally, thecementitious material may be present in the cement slurries describedherein to achieve a cement slurry density in the range of from a lowerlimit of about 9.0 pounds per gallon (“ppg”), 10 ppg, 11 ppg, 12 ppg, 13ppg, 14 ppg, 15 ppg, 16 ppg, and 17 ppg to an upper limit of about 25ppg, 24 ppg, 23 ppg, 22 ppg, 21 ppg, 20 ppg, 19 ppg, 18 ppg, and 17 ppg.

In some embodiments, the cement slurry may additionally comprise apozzolanic material. Pozzolanic materials may aid in increasing thedensity and strength of the cementitious material. As used herein, theterm “pozzolanic material” refers to a siliceous material that, whilenot being cementitious, is capable of reacting with calcium hydroxide(which may be produced during hydration of the cementitious material).Because calcium hydroxide accounts for a sizable portion of mosthydrated hydraulic cements and because calcium hydroxide does notcontribute to the cement's properties, the combination of cementitiousand pozzolanic materials may synergistically enhance the strength andquality of the cement. Any pozzolanic material that is reactive with thecementitious material may be used in the embodiments herein. Suitablepozzolanic materials may include, but are not limited to silica fume,metakaolin, fly ash, diatomaceous earth, calcined or uncalcineddiatomite, calcined fullers earth, pozzolanic clays, calcined oruncalcined volcanic ash, bagasse ash, pumice, pumicite, rice hull ash,natural and synthetic zeolites, slag, vitreous calcium aluminosilicate,and any combinations thereof. In some embodiments, the pozzolanicmaterial may be present in an amount in the range of a lower limit ofabout 5%, 7.5%, 10%, 12.5%, 15%, 17.5%, 20%, 22.5%, 25%, 27.5%, 30%, and32.5% to an upper limit of about 60%, 57.5%, 55%, 52.5%, 50%, 47.5%,45%, 42.5%, 40%, 37.5%, 35%, and 32.5% by weight of the dry cementitiousmaterial.

In some embodiments, the cement slurry may further comprise any cementadditive for use in forming a curable cement slurry. Cement additivesmay be added in order to modify the characteristics of the cementslurry, for example. Such cement additives include, but are not limitedto, a defoamer; a cement accelerator; a cement retarder; a fluid-lossadditive; a cement dispersant; a cement extender; a weighting agent; alost circulation additive; and any combination thereof. The cementadditives of the embodiments herein may be in any form, including dryform or liquid form.

The process of determining the theoretical first wellbore radius duringexposure to the treatment fluid and the theoretical second wellboreradius during cementing with the proposed cement slurry is based on saltcreep analysis in the presence of formation-treatment fluid andformation-liquid cement slurry, respectively. In addition, as describedin more detail below, the theoretical thermal and thermo-mechanicalproperties of the proposed cement slurry are determined based on saltcreep analysis in the presence of formation-hardened cement sheath. Saltcreep can be divided into three distinct states: primary, secondary, andtertiary. Primary salt creep (also known as transient salt creep) ischaracterized by high deformation in a short period of time. As thetreatment fluid or cement slurry is subjected to constant loading, therate of deformation increases at a decreasing rate until it reaches asteady state of deformation, known as secondary salt creep. Secondarysalt creep is the longest stage with respect to time and is where strainrate tends to become constant. Finally, tertiary salt creep ischaracterized at the point in which the rate of deformation increasesexponentially until failure of salt is reached. Accordingly, tertiarysalt creep causes a volume increase due to fracturing (e.g.,microfracturing) in the formation and leads to material failure. Thesalt creep analysis performed in the methods of the present disclosuremay preferably take into account only secondary salt creep, which is themost dominant and lengthy stage for preparation of a final cement slurryaccording to the embodiments herein. In other embodiments, however,tertiary salt creep may also be considered during the salt creepanalyses described herein, particularly to evaluate differenttemperatures and stress loading. In yet other embodiments, primary saltcreep may be used in the salt creep analyses; however, primary saltcreep tends to be quite short lived and may have very little, if any,effect on the value of the theoretical first or second wellbore radius.Accordingly, the salt creep analysis may take into account secondarysalt creep only, secondary and tertiary salt creep only, or all threestages of salt creep, without departing from the scope of the presentdisclosure.

Secondary salt creep can be determined using the following model:

$\begin{matrix}{{\overset{.}{ɛ}}_{2} = {{A_{1}{\exp\left( \frac{- Q_{1}}{RT} \right)}\left( \frac{S_{2}}{S_{2}^{o}} \right)^{n_{1}}} + {A_{2}{\exp\left( \frac{- Q_{2}}{RT} \right)}\left( \frac{S_{2}}{S_{2}^{o}} \right)^{n_{2}}}}} & {{Model}\mspace{14mu} 1}\end{matrix}$

where is the second invariant of deviatoric strain; S₂ is the secondinvariant of deviatoric creep strain; Q₁ is the activation energy forthe first creep mechanism; Q₂ is the activation energy for the secondcreep mechanism; and A₁, A₂, n₁, n₂, and S₂ ⁰ are material constants forthe particular salt type in the formation. The material constants aredetermined using uni-axial and tri-axial creep tests on extracted saltformation cores. One of skill in the art will understand the tests to beperformed, as no single standard procedure is available. As such, thematerial constants may be determined by one of skill in the art and theoutcome generally depends greatly on the procedure followed duringtesting. Accordingly, it may be best to report results of uni- andtri-axial creep tests along with testing protocol. The stress and straininvariants are mathematically connected to individual stresses andstrains, such relationships being available in any standard mechanicalengineering textbook and known to those of skill in the art. There is nostandard equation(s) for tertiary salt creep because it is a failurephenomenon, however, one of skill in the art will understand how tocalculate such tertiary salt creep, if it is desired to be used in themethods described herein, based on such factors as the failing salttype, the amount of failing salt, and the like. While Model 1 is one ofthe salt creep models available, as known to those of skill in the art,for example, there are other models that may be used in the methods ofthe present disclosure. For example, some salt creep models are based onmicroscopic deformation mechanisms, while others are purely empirical orcombinations thereof. The methods disclosed herein are not limited touse of the salt creep analysis defined by Model 1, but any existing ornew models defining creeping phenomenon may be used, as the model itselfdoes not affect the method followed, but merely changes the modelequation used.

After determining the theoretical first and second wellbore radius, arheology of the proposed cement slurry versus salt dissolution curve(which may be referred to herein as “rheology v. salt dissolutioncurve”) is experimentally determined. A salt dissolution is presented asa percentage. Accordingly, the rheology of the proposed cement slurryand the percent of salt dissolution into the cement slurry varytogether. As used herein, “rheology” refers to the flow of matter,particularly in the liquid or semi-liquid state. Certain rheologyparameters may be used to determine the rheology of the treatment fluidsand/or cement slurries of the present disclosure. Selection of the typeof rheology parameters for use may depend on a number of factorsincluding, but not limited to, the specific type and composition of thetreatment fluid and/or cement slurry, the type and composition of thesubterranean salt composition, and the like. Suitable rheologyparameters that may be used in determining the various rheology curvesdisclosed herein, including those discussed below, include, but are notlimited to, plastic viscosity, Bingham model yield point,Herschel-Bulkley model parameters, and any combination thereof.

The salt dissolution vs. rheology curve of the proposed cement slurrymay be determined, for example, by providing a salt core designed tomimic the subterranean salt formation. The salt core may be prepared,such as by pouring salt in a test cell and compressing the salt into acore at about 15,000 psi, or the salt core may be an actual salt corefrom the formation. The salt core may then be attached to the shaft of ahigh-pressure, high-temperature (“HPHT”) consistometer. Although use ofan HPHT consistometer for determining the salt dissolution vs. rheologycurve of the methods described herein may be used, other approaches mayadditionally be used, without departing from the scope of the presentdisclosure, that are capable of determining rheology of a treatmentfluid (e.g., a drilling fluid) and a cement slurry having a known amountof salt dissolved therein. The proposed cement slurry may be mixedaccording to the American Petroleum Institute, Recommended Procedure10B-2. The rheology of the proposed cement slurry is measured using arheometer before subjecting it to salt dissolution and then transferredto the HPHT consistometer cup. The procedure for determining rheologymay be dependent upon the particular type of rheometer used. The shaftwith the salt core attached is immersed in the proposed cement slurryand conditioned in the HPHT consistometer under expected downholetemperature and pressure conditions for the expected contact time (i.e.,based on the expected conditions and contact time for the actualcementing job). The rheology of the proposed cement slurry withdissolved salt is then measured after conditioning. The difference inthe rheology of the proposed cement slurry before and after saltdissolution represents the effect of salt dissolution on the slurry andis used to form the rheology v. salt dissolution curve.

After determining the rheology vs. salt dissolution curve, either of thefollowing two options may be pursued. First, (“Option 1”) may beemployed by determining experimentally a salt dissolution versus flowrate curve based on laboratory experiments and solving aconvection-diffusion equation. To obtain salt dissolution vs. flow ratecurve using Option 1, any method that combines experimentation and aconvection-diffusion equation may be used in accordance with the methodsdescribed herein. In one such method, the following steps may beperformed to determine the salt dissolution vs. flow rate curve. First,a shaped synthetic or extracted salt core of known weight that mimicsthe desired formation may be obtained. In some embodiments, the saltcore may be cylindrical in shape, but any simple geometry that may beeasily represented mathematically may be used in accordance with themethods described herein. Thereafter, either treatment fluid or cementslurry may be flowed across the core at a desired flow rate for adesired amount of time and then the remaining weight of the salt coremay be determined to quantify the amount of salt dissolved. This weightcalculation may be repeated using different flow rates and amounts oftime, thereby experimentally obtaining a salt dissolution vs. flow ratecurve. In some embodiments, temperature may be expected to be a factorin a particular subterranean formation; in such cases, the salt core maybe subjected to expected temperatures to take into account temperatureeffects. These experiments thus take into account the amount of saltdissolution from the salt core as a factor of time, flow rate,concentration of salt in the core, concentration of salt in thetreatment fluid and/or cement slurry, temperature, and other inherentdiffusivity between the salt core and the treatment fluid and/or cementslurry.

However, the salt is also diffusing into the treatment fluid and/orcement slurry. As such, a combined convection-diffusion equation may besolved using the same flow rate conditions and core geometry as theexperiments. Any convection-diffusion model known to those of skill inthe art, with the benefit of the present disclosure, may be usedaccording to the methods described herein. As an example, a suitablegeneral convention-diffusion equation that may be used follows:

$\begin{matrix}{\frac{\partial c}{\partial t} = {{\nabla{\cdot \left( {D{\nabla c}} \right)}} - {\nabla{\cdot \left( {\overset{\rightarrow}{v}c} \right)}} + R}} & {{Equation}\mspace{14mu} 1}\end{matrix}$

wherein c is the concentration of salt in the treatment fluid and/orcement slurry when it is flowing with a velocity (or flow rate),represented by {right arrow over (ν)} in the presence of some masssource or sink R, represented in the methods herein as the salt core (orformation) itself. Diffusivity is represented by the unknown D, which isback-fit in the equation such that the mathematical equation predictsthe same amount of salt dissolution determined experimentally. Theback-fit can be performed for various flow rates and at differenttemperatures. Accordingly, the salt dissolution (or diffusivity) vs.flow rate curve may be obtained. Simplified versions of Equation 1 mayalso be utilized, according to one of skill in the art. For any givenflow rate (and temperature, if required), the salt dissolution valuedepends only on salt-fluid combinations (i.e., the type of saltformation and the composition of a treatment fluid and/or cement slurry)and, thus, the salt dissolution value mimics the actual salt dissolutionthat would be experienced in the wellbore of the actual formation.

Second, “Option 2” may be employed, involving calculating a maximum saltdissolution value based on thermodynamic salt dissolution, as known tothose of skill in the art. Thermodynamic salt dissolution determines themaximum concentration of one species (e.g., salt concentration in themethods described herein) dissolved in a solvent in the presence ofother species. For simple solutes dissolved in simple solvents,theoretical equations are available in standard textbooks addressing thelaws of thermodynamics. For complex solute and solvent combinations,available literature addressing the laws of thermodynamics extend thesesimple equations, and are known and available to those of skill in theart. If such extended equations are required based on the solute andsolvent combinations of the fluids (e.g., treatment fluid or cementslurry) used in the models described herein, the specific extendedequation for such specific solute and solvent combinations would beused. For example, for pure halite dissolved in a cement slurry, thesolute is NaCl and the solvent is water with a combination of calcium,silicon, aluminum, and magnesium species.

Next, regardless of whether Option 1 or Option 2 above are used, atheoretical final wellbore radius of the subterranean salt formation iscalculated based on the theoretical first wellbore radius, thetheoretical second wellbore radius, and salt dissolution. That is, thetheoretical first wellbore radius, the theoretical second wellboreradius, and salt dissolution from the formation and into the treatmentfluid and/or the proposed cement slurry are used as inputs to determinethe theoretical final wellbore radius. The theoretical final wellboreradius is determined merely by simple addition and subtraction of thewellbore opening and closing, respectively, as determined by theoreticalfirst and second wellbore radii and salt dissolution. This theoreticalfinal wellbore radius takes into account both the theoretical first andsecond wellbore radius and the effects of salt dissolution, which asexplained above, may result in an increased radius, as the salt flowsfrom the formation and into the treatment fluid and/or cement slurry.However, after the cement slurry has fully hydrated into a cementsheath, the cement sheath is no longer able to accept dissolved saltsand, thus, a theoretical final wellbore radius may be determined.

If Option 1 is used, next a rheology of the proposed cement slurryversus flow rate curve is determined, by taking into account both therheology v. salt dissolution curve and the salt dissolution v. flow ratecurve described previously. If Option 2 is used, flow rate is notrelevant, as only the maximum salt dissolution possible was calculatedusing the thermodynamic salt dissolution model.

A second alternate series of steps may follow, regardless of whetherOption 1 or Option 2 are selected previously—“Option 3” and “Option 4.”Option 3 involves the ordered steps of: (a) theoretically determiningthe thermal and thermo-mechanical properties of the proposed cementslurry based on salt creep analysis in the presence of formation-cementsheath to determine whether the proposed cement sheath is capable ofwithstanding the wellbore load, (b) experimentally determining whetherthe proposed cement slurry, once set into a sheath, can actuallywithstand the wellbore load based on an ultrasonic cement analyzer(“UCA”) strength test and actual thermal and thermo-mechanicalproperties of the proposed cement slurry after salt dissolution, asexplained above, (c) theoretically determining a theoretical pumppressure and pump time for the treatment fluid and the proposed cementslurry based on a computational fluid dynamics model, wherein thetheoretical pump pressure for the treatment fluid and the cement slurryis between the pore pressure and fracture gradient of the subterraneansalt formation, and wherein the theoretical pump time for the treatmentfluid and the proposed cement slurry is such that the proposed cementsheath is theoretically capable of forming a cement sheath withoutsubstantial premature curing, and (d) experimentally determining whetherthe theoretical pumping time for the treatment fluid and the proposedcement slurry will permit formation of the proposed cement sheath in thewellbore without substantial premature curing based on a thickening timetest according to the American Petroleum Institute, RecommendedProcedure 10B-2.

The theoretical thermal and thermo-mechanical properties of the proposedcement slurry based on salt creep analysis in the presence offormation-cement sheath is determined based on scientifically availablehistorical data related to such properties of similar cement slurriesthat have been used in the past and tested. The theoretical thermal andthermo-mechanical properties based on historical data is comparedagainst the wellbore load that is expected to be exerted on the curedcement sheath and if the proposed cement slurry is not expected toendure such loads without failure, the composition of the cement slurrymay be manipulated and new theoretical thermal and thermo-mechanicalproperties determined based on historically available data fromsimilarly composed, previously tested cement slurries.

Experimentally determining whether the proposed cement slurry, once setinto a sheath, can actually withstand the wellbore load may be based onan ultrasonic cement analyzer (“UCA”) strength test and actual thermaland thermo-mechanical properties of the cement sheath. The actualthermal and thermo-mechanical properties are determined by curing thecement slurry and performing a battery of tests to determine whetherfailure is likely. Such tests include, uniaxial experiments, triaxialexperiments, tensile strength testing, thermal conductivity and specificheat and thermal expansion testing, and shrinkage testing. Such testingmay be performed according to the American Society for Testing andMaterials procedures D3148-02, D2664-95a, and D3148-02. Determiningexperimentally whether the proposed cement slurry, once set into asheath, can actually withstand the wellbore load is particularlylaborious and is preferably performed only after determining that thecement slurry is likely to withstand such load, thereby reducing thelikelihood of having to repeat the step, although repeating the stepdoes not depart from the scope of the present disclosure.

Theoretically determining a theoretical pump pressure and pump time forthe treatment fluid and the proposed cement slurry based on acomputational fluid dynamics model may utilize any such model known tothose of skill in the art that are capable of predicting fluid flows.For example, a suitable model may utilize the Navier-Stokes equations,defining single-phase and/or multi-phase fluid flow of both miscible andimmiscible fluids. These equations may further be simplified, withoutdeparting from the scope of the present invention, such as by utilizingEuler equations. Existing commercial software like ANSYS FLUENT®,available from Ansys, Inc. in Canonsburg, Pa. or COMSOL MULTIPHYSICS®,available from Comsol, Inc. in Burlington, Mass.

Option 4, which is merely a change in the order of operations comparedto Option 3, involves the ordered steps of: (a) theoreticallydetermining a theoretical pump pressure and pump time for the treatmentfluid and the proposed cement slurry based on a computational fluiddynamics model, wherein the theoretical pump pressure for the treatmentfluid and the cement slurry is between the pore pressure and fracturegradient of the subterranean salt formation, and wherein the theoreticalpump time for the treatment fluid and the proposed cement slurry is suchthat the proposed cement sheath is theoretically capable of forming acement sheath without substantial premature curing, (b) experimentallydetermining whether the theoretical pumping time for the treatment fluidand the proposed cement slurry will permit formation of the proposedcement sheath in the wellbore without substantial premature curing basedon a thickening time test, (c) theoretically determining the thermal andthermo-mechanical properties of the proposed cement slurry based on saltcreep analysis in the presence of formation-cement sheath to determinewhether the proposed cement sheath is capable of withstanding thewellbore load, and (d) experimentally determining whether the proposedcement slurry, once set into a sheath, can actually withstand thewellbore load based on an ultrasonic cement analyzer test and actualthermal and thermo-mechanical properties of the proposed cement slurryafter salt dissolution.

The thermal and thermo-mechanical properties of the proposed cementslurry based on salt creep analysis in the presence of formation-cementsheath to determine whether the proposed cement sheath is capable ofwithstanding the wellbore load may be calculated based on one or more ofthermal conductivity, thermal diffusivity, tensile strength, compressivestrength, hydration volume change, Young's modulus, and Poisson's ratio.

The computational fluid dynamics model used to determine the theoreticalpump time and pressure of the treatment fluid and the proposed cementslurry to ensure that the proposed cement slurry may form a sheathwithout substantial premature curing may use as inputs the flow rate ofthe treatment fluid, the flow rate of the proposed cement slurry, therheology of the treatment fluid, the rheology of the proposed cementslurry, the standoff profile, and the theoretical final wellbore radius.Often, the flow rate is dictated by the operator or wellbore owner,considering such factors as equipment limitations, the type andcomposition of the treatment fluid and proposed cement slurry (e.g.,viscosity), the type of formation, and the like. The rheology of thetreatment fluid and proposed cement may be based on the same rheologyparameters used to form the curves described previously herein. Suchrheology parameters may include, but are not limited to, plasticviscosity, Bingham model yield point, Herschel-Bulkley model parameters,and any combination thereof. As used herein, the term “standoff profile”refers to the space between the face of the subterranean salt formationand the casing string, in which the cement sheath is to be formed. Insome embodiments, in addition to or in lieu of manipulating the proposedcement slurry at one or more steps in Option 3 or Option 4, as describedin more detail below, the flow rate of the treatment fluid and/orproposed cement slurry may be manipulated and the computational fluiddynamics model repeated with the new flow rate to determine if the newflow rate permits the proposed cement slurry to form a sheath withoutsubstantial premature curing. For example, in some embodiments, meremanipulation of the flow rate of one or both of the treatment fluid andthe proposed cement slurry may be sufficient without furthermanipulating the slurry.

The difference between Option 3 and Option 4, as stated above, is thateither the ability of the proposed cement slurry to withstand thewellbore load after curing into a cement sheath is first theoretically(e.g., by performing calculations and modeling) and then experimentallytested, followed by determining the pumping pressure and time of thetreatment fluid and/or proposed cement slurry is theoretically and thenexperimentally, or vice versa. In both cases, theoretical calculationsare preferably made before experimental testing is performed for anygiven parameter (i.e., the ability of the cement sheath to withstandwellbore loads, or the pumping time and pressure). Performing thetheoretical calculations before experimental testing allows an operatorto manipulate the proposed cement slurry after one or both of steps (a)and (c). If Option 3 is selected, the proposed cement slurry may bemanipulated after step (a) until the proposed cement sheath istheoretically capable of withstanding the wellbore load and/or afterstep (c) until the proposed cement sheath is capable of forming withoutsubstantial premature curing (e.g., cures in the desired location). IfOption 4 is selected, the proposed cement slurry may be manipulatedafter step (a) until the proposed cement sheath is capable of formingwithout substantial premature curing and/or after step (c) until theproposed cement sheath is theoretically capable of withstanding thewellbore load (i.e., the proposed cement is manipulated after step (a)and/or (c) and then reexamined theoretically by repeating steps (a)and/or (c) based on the manipulated proposed cement slurry). Moreover,the proposed cement slurry may be manipulated multiple times after oneor both of steps (a) and (c) in both options until a proposed cementslurry with desirable characteristics is achieved.

Ideally, the manipulation of the cement slurry at one or both of steps(a) and (c) may prevent repetition of the experimental steps of (b) and(d). In some embodiments, however, the cement slurry may be manipulatedafter one or both of steps (b) and (d). If Option 3 is selected, theproposed cement slurry many be manipulated after step (b) until theproposed cement slurry, once set into a sheath, can actually withstandthe wellbore load and/or step (d) until the theoretical pumping time forthe treatment fluid and the proposed cement slurry will permit formationof the proposed cement sheath in the wellbore without substantialpremature curing based on a thickening time test. If Option 4 isselected, the proposed cement slurry may be manipulated after one orboth of steps (b) until the theoretical pumping time for the treatmentfluid and the proposed cement slurry will permit formation of theproposed cement sheath in the wellbore without substantial prematurecuring based on a thickening time test and/or (d) until the proposedcement slurry, once set into a sheath, can actually withstand thewellbore load. Ideally, the step of experimentally determining whetherthe proposed cement slurry, once set into a sheath, can actuallywithstand the wellbore load is performed only once, as the experimentaltest may be costly in terms of economics and time. Accordingly, in someembodiments, the proposed cement slurry may be manipulated after one ormore of the steps in Option 3 or Option 4 without substantiallyaffecting the thermal and thermo-mechanical properties (e.g., theintegrity of the cured sheath), so as to avoid repeating once or moretimes the step of experimentally determining whether the cement slurrycan form a cement sheath capable of withstanding the wellbore load.

In each case where the proposed cement slurry is manipulated at one ormore of steps (a)-(d) of Option 3 or Option 4, the manipulated proposedcement slurry must be reevaluated to determine the rheology v. saltdissolution curve, the salt dissolution v. flow rate curve or themaximum salt dissolution as determined by thermodynamic saltdissolution, the rheology v. flow rate curve, if applicable (i.e., ifOption 1 above is used), and the theoretical final wellbore radius, asdiscussed in detail previously. This is so because the results of thosecurves and/or parameters are needed to theoretically determine steps (a)and (c) of Option 3 and Option 4 (i.e., they provide inputs for latercalculations).

The proposed cement slurry may be manipulated at any one or more stages,as described in the present disclosure, by altering one or more of theamount, type, presence, or absence of one or more components of theslurry (e.g., the base fluid, the cementitious material, the pozzolanicmaterial, the cement additive, and any combination thereof). That is, insome embodiments, the type of base fluid may be changed or adjusted(e.g., adding fresh water to seawater). In other embodiments, apozzolanic material may be added when it was not present before, thetype of cementitious material may be completely changed or a new blendproposed, a cement additive may be removed or added from the treatmentfluid, and the like. The combinations of changes are not limited and oneof skill in the art, with the benefit of this disclosure, willunderstand how those changes will affect the proposed cement slurry,with an eye toward bringing into compliance with the model disclosedherein.

Finally, after manipulating the proposed cement slurry and/or the flowrate of the treatment fluid and/or the proposed cement slurry, asdescribed herein, a final cement slurry is established. Accordingly, thefinal cement slurry may be designed such that it will actually withstandthe wellbore loads in a particular subterranean salt formation and willnot substantially cure prematurely in an undesirable location in theformation, both of which contribute to the integrity of the cementsheath and the ability of the sheath to maintain zonal isolation. Afinal pumping pressure and time for the treatment fluid and the finalcement slurry may also be established. Thereafter, where the treatmentfluid is a drilling fluid, for example, a wellbore may be drilled usingthe drilling fluid at the pumping time and pressure established for thedrilling fluid and the cementing operation may be performed using thefinal cement slurry at the pumping time and pressure established for thefinal cement slurry. It should be noted that the pumping time andpressure for the treatment fluid and the final cement slurry need notbe, but can be, equivalent.

In various embodiments, systems configured for preparing, transporting,and delivering the final cement slurries described herein to a downholelocation are described. In various embodiments, the systems can comprisea pump fluidly coupled to a tubular (e.g., a casing, drill pipe,production tubing, coiled tubing, etc.) extending into a wellborepenetrating a subterranean formation, the tubular may be configured tocirculate or otherwise convey a final cement slurry prepared asdescribed herein. The pump may be, for example, a high pressure pump ora low pressure pump, which may depend on, inter alia, the viscosity anddensity of the final cement slurry, the type of the cementing operation,and the like.

In some embodiments, the systems described herein may further comprise amixing tank arranged upstream of the pump and in which the final cementslurry is formulated. In various embodiments, the pump (e.g., a lowpressure pump, a high pressure pump, or a combination thereof) mayconvey the final cement slurry from the mixing tank or other source ofthe final cement slurry to the tubular. In other embodiments, however,the final cement slurry can be formulated offsite and transported to aworksite, in which case the final cement slurry may be introduced to thetubular via the pump directly from a transport vehicle or a shippingcontainer (e.g., a truck, a railcar, a barge, or the like) or from atransport pipeline. In yet other embodiments, the final cement slurrymay be formulated on the fly at the well site where components of thefinal cement slurry are pumped from a transport (e.g., a vehicle orpipeline) and mixed during introduction into the tubular. In any case,the final cement slurry may be drawn into the pump, elevated to anappropriate pressure, and then introduced into the tubular for deliverydownhole.

FIG. 1 shows an illustrative schematic of a system that can deliverfinal cement slurry of the present invention to a downhole location,according to one or more embodiments. It should be noted that while FIG.1 generally depicts a land-based system, it is to be recognized thatlike systems may be operated in subsea locations as well. As depicted inFIG. 1, system 1 may include mixing tank 10, in which a final cementslurry of the present invention may be formulated. Again, in someembodiments, the mixing tank 10 may represent or otherwise be replacedwith a transport vehicle or shipping container configured to deliver orotherwise convey the final cement slurry to the well site. The finalcement slurry may be conveyed via line 12 to wellhead 14, where thefinal cement slurry enters tubular 16 (e.g., a casing, drill pipe,production tubing, coiled tubing, etc.), tubular 16 extending fromwellhead 14 into wellbore 22 penetrating subterranean formation 18. Uponbeing ejected from tubular 16, the final cement slurry may subsequentlyreturn up the wellbore in the annulus between the tubular 16 and thewellbore 22 as indicated by flow lines 24. In other embodiments, thefinal cement slurry may be reverse pumped down through the annulus andup tubular 16 back to the surface, without departing from the scope ofthe disclosure. Pump 20 may be configured to raise the pressure of thefinal cement slurry to a desired degree before its introduction intotubular 16 (or annulus). It is to be recognized that system 1 is merelyexemplary in nature and various additional components may be presentthat have not necessarily been depicted in FIG. 1 in the interest ofclarity. Non-limiting additional components that may be present include,but are not limited to, supply hoppers, valves, condensers, adapters,joints, gauges, sensors, compressors, pressure controllers, pressuresensors, flow rate controllers, flow rate sensors, temperature sensors,and the like.

One skilled in the art, with the benefit of this disclosure, shouldrecognize the changes to the system described in FIG. 1 to provide forother cementing operations (e.g., squeeze operations, reverse cementing(where the cement is introduced into an annulus between a tubular andthe wellbore and returns to the wellhead through the tubular), and thelike).

It is also to be recognized that the disclosed final cement slurries mayalso directly or indirectly affect the various downhole equipment andtools that may come into contact with the treatment fluids duringoperation. Such equipment and tools may include, but are not limited to,wellbore casing, wellbore liner, completion string, insert strings,drill string, coiled tubing, slickline, wireline, drill pipe, drillcollars, mud motors, downhole motors and/or pumps, surface-mountedmotors and/or pumps, centralizers, turbolizers, scratchers, floats(e.g., shoes, collars, valves, etc.), wellbore projectiles (e.g.,wipers, plugs, darts, balls, etc.), logging tools and related telemetryequipment, actuators (e.g., electromechanical devices, hydromechanicaldevices, etc.), sliding sleeves, production sleeves, plugs, screens,filters, flow control devices (e.g., inflow control devices, autonomousinflow control devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like. Any of thesecomponents may be included in the systems generally described above anddepicted in FIG. 1.

Embodiments disclosed herein include Embodiment A and Embodiment B.

Embodiment A

A method comprising: (a) calculating a theoretical first wellbore radiusin a subterranean salt formation having a treatment fluid therein basedon salt creep analysis in the presence of formation-treatment fluid; (b)calculating a theoretical second wellbore radius in the subterraneansalt formation during a cementing operation with a proposed cementslurry based on salt creep analysis in the presence of formation-cementslurry, wherein the cementing operation involves forming a proposedcement sheath within the wellbore, and wherein the proposed cementsheath must withstand a wellbore load to prevent failure of the cementsheath in the wellbore; (c) determining experimentally a rheology of theproposed cement slurry versus salt dissolution curve; (d) determiningexperimentally and based on a convection-diffusion equation a saltdissolution versus flow rate curve; (e) calculating a theoretical finalwellbore radius in the subterranean salt formation based on thetheoretical first wellbore radius, the theoretical second wellboreradius, and salt dissolution after forming the proposed cement sheath;(f) determining a rheology of the proposed cement slurry versus flowrate curve; (g) calculating theoretically whether the proposed cementsheath is capable of withstanding the wellbore load by calculatingtheoretical thermal and thermo-mechanical properties of the proposedcement slurry based on salt creep analysis in the presence offormation-cement sheath; (h) determining experimentally whether theproposed cement sheath is capable of withstanding the wellbore loadbased on an ultrasonic cement analyzer test and actual thermal andthermo-mechanical properties of the proposed cement slurry after saltdissolution; (i) calculating theoretically a theoretical pump time and atheoretical pump pressure for the treatment fluid and the proposedcement slurry based on a computational fluid dynamics model, wherein thetheoretical pump pressure for the treatment fluid and the proposedcement slurry is between a pore pressure and a fracture gradient of thesubterranean salt formation, and wherein the theoretical pump time forthe treatment fluid and the proposed cement slurry is such that theproposed cement slurry will theoretically permit formation of theproposed cement sheath in the wellbore without substantial prematurecuring; (j) determining experimentally whether the theoretical pumpingtime for the treatment fluid and the proposed cement slurry will permitformation of the proposed cement sheath in the wellbore withoutsubstantial premature curing based on a thickening time test of theproposed cement slurry; (k) performing steps (g)-(h) before steps(i)-(j), or performing steps (i)-(j) before steps (g)-(h); (l)establishing a final cement slurry, a final pumping pressure and timefor the treatment fluid, and a final pumping pressure and time for thecement slurry; (m) performing a wellbore operation with the treatmentfluid using the final pumping time and pressure for the treatment fluid;and (n) performing the cementing operation with the final cement slurryusing the final pumping time and pressure for the final cement slurry.

Embodiment A may have one or more of the following additional elementsin any combination:

Element A1: Wherein step (k) comprises performing steps (g)-(h) beforesteps (i)-(j), and further comprising manipulating the proposed cementslurry after at least one of: step (g), and repeating steps (b)-(g)until the proposed cement sheath based on the proposed cement slurrythat has been manipulated is theoretically capable of withstanding thewellbore load, step (h), and repeating steps (b)-(h) until the proposedcement sheath based on the proposed cement slurry that has beenmanipulated is experimentally capable of withstanding the wellbore load,

step (i), and repeating steps (b)-(i) until the theoretical pumpingpressure for the treatment fluid and the proposed cement slurry that hasbeen manipulated is theoretically between the pore pressure and thefracture gradient of the subterranean salt formation and the theoreticalpumping time for the treatment fluid and the proposed cement slurry thathas been manipulated theoretically permits formation of the proposedcement sheath with the proposed cement slurry that has been manipulatedin the wellbore without substantial premature curing, and step (j), andrepeating steps (b)-(j) until the theoretical pumping timeexperimentally permits formation of the proposed cement sheath in thewellbore with the proposed cement slurry that has been manipulatedwithout substantial premature curing.

Element A2: Wherein step (k) comprises performing steps (i)-(j) beforesteps (g)-(h), and further comprising manipulating the proposed cementslurry after at least one of: step (i), and repeating steps (b)-(f) and(i) until the theoretical pumping pressure for the treatment fluid andthe proposed cement slurry that has been manipulated is theoreticallybetween the pore pressure and the fracture gradient of the subterraneansalt formation and the theoretical pumping time for the treatment fluidand the proposed cement slurry that has been manipulated theoreticallypermits formation of the proposed cement sheath with the proposed cementslurry that has been manipulated in the wellbore without substantialpremature curing, step (j), and repeating steps (b)-(f) and (i)-(j)until the theoretical pumping time experimentally permits formation ofthe proposed cement sheath in the wellbore with the proposed cementslurry that has been manipulated without substantial premature curing,step (g), and repeating steps (b)-(f), (i)-(j), and (g) until theproposed cement sheath based on the proposed cement slurry that has beenmanipulated is theoretically capable of withstanding the wellbore load,and step (h), and repeating steps (b)-(i)-(j), and (g)-(h) until theproposed cement sheath based on the proposed cement slurry that has beenmanipulated is experimentally capable of withstanding the wellbore load.

Element A3: Wherein the computational fluid dynamics model of step (i)is used to determine the theoretical pump time and pressure of thetreatment fluid and the proposed cement slurry based on: a flow rate ofthe treatment fluid, a flow rate of the proposed cement slurry, rheologyparameters of the treatment fluid, rheology parameters of the proposedcement slurry, a standoff profile, and the theoretical final wellboreradius.

Element A4: Wherein at least one of the flow rate of the treatment fluidand the flow rate of the cement slurry are manipulated and step (i) isrepeated.

Element A5: Wherein the rheology parameters of the treatment fluid andthe rheology parameters of the proposed cement slurry are selected fromthe group consisting of plastic viscosity, Bingham model yield point,Herschel-Bulkley model parameters, and any combination thereof.

Element A6: Wherein the theoretical thermal and thermo-mechanicalproperties of the proposed cement are calculated based on at least oneof thermal conductivity, thermal diffusivity, tensile strength,compressive strength, hydration volume change, Young's modulus, andPoisson's ratio.

Element A7: Wherein the salt creep analysis is based on secondary saltcreep; a combination of secondary salt creep and tertiary salt creep; ora combination of primary salt creep, secondary salt creep, and tertiarysalt creep.

Element A8: Wherein rheology parameters of the proposed cement slurryare used in step (c) to determine experimentally the rheology of theproposed cement slurry versus salt dissolution curve, and wherein therheology parameters are selected from the group consisting of plasticviscosity, Bingham model yield point, Herschel-Bulkley model parameters,and any combination thereof.

Element A9: Further comprising a wellhead with a tubular extendingtherefrom and into the wellbore, and a pump fluidly coupled to thetubular; and wherein step (n) is performed by introducing the finalcement slurry into the wellbore through the tubular.

By way of non-limiting example, exemplary combinations applicable toEmbodiment A include: combinations of A with A1 and A4; A with A1, A3,and A9; A with A1, A6, A7, and A8; A with A2, A3, A4, and A9; A with A2,A7 and A8; A2 with A6.

Embodiment B

A method comprising: (a) calculating a theoretical first wellbore radiusin a subterranean salt formation having a treatment fluid therein basedon salt creep analysis in the presence of formation-treatment fluid; (b)calculating a theoretical second wellbore radius in the subterraneansalt formation during a cementing operation with a proposed cementslurry based on salt creep analysis in the presence of formation-cementslurry, wherein the cementing operation involves forming a proposedcement sheath within the wellbore, and wherein the proposed cementsheath must withstand a wellbore load to prevent failure of the cementsheath in the wellbore; (c) determining experimentally a rheology of theproposed cement slurry versus salt dissolution curve; (d) calculating amaximum salt dissolution value based on thermodynamic salt dissolution;(e) calculating a theoretical final wellbore radius in the subterraneansalt formation based on the theoretical first wellbore radius, thetheoretical second wellbore radius, and salt dissolution after formingthe proposed cement sheath; (f) calculating theoretically whether theproposed cement sheath is capable of withstanding the wellbore load bycalculating theoretical thermal and thermo-mechanical properties of theproposed cement slurry based on salt creep analysis in the presence offormation-cement sheath; (g) determining experimentally whether theproposed cement sheath is capable of withstanding the wellbore loadbased on an ultrasonic cement analyzer test and actual thermal andthermo-mechanical properties of the proposed cement slurry after saltdissolution; (h) calculating theoretically a theoretical pump time and atheoretical pump pressure for the treatment fluid and the proposedcement slurry based on a computational fluid dynamics model, wherein thetheoretical pump pressure for the treatment fluid and the proposedcement slurry is between a pore pressure and a fracture gradient of thesubterranean salt formation, and wherein the theoretical pump time forthe treatment fluid and the proposed cement slurry is such that theproposed cement slurry will theoretically permit formation of theproposed cement sheath in the wellbore without substantial prematurecuring; (i) determining experimentally whether the theoretical pumpingtime for the treatment fluid and the proposed cement slurry will permitformation of the proposed cement sheath in the wellbore withoutsubstantial premature curing based on a thickening time test of theproposed cement slurry; (j) performing steps (f)-(g) before steps(h)-(i), or performing steps (h)-(i) before steps (f)-(g); (k)establishing a final cement slurry, a final pumping pressure and timefor the treatment fluid, and a final pumping pressure and time for thecement slurry; (l) performing a wellbore operation with the treatmentfluid using the final pumping time and pressure for the treatment fluid;and (m) performing the cementing operation with the final cement slurryusing the final pumping time and pressure for the final cement slurry.

Embodiment B may have one or more of the following additional elementsin any combination:

Element B1: Wherein step (j) comprises performing (f)-(g) before steps(h)-(i), and further comprising manipulating the proposed cement slurryafter at least one of: step (f), and repeating steps (b)-(f) until theproposed cement sheath based on the proposed cement slurry that has beenmanipulated is theoretically capable of withstanding the wellbore load,

step (g), and repeating steps (b)-(g) until the proposed cement sheathbased on the proposed cement slurry that has been manipulated isexperimentally capable of withstanding the wellbore load, step (h), andrepeating steps (b)-(h) until the theoretical pumping pressure for thetreatment fluid and the proposed cement slurry that has been manipulatedis theoretically between the pore pressure and the fracture gradient ofthe subterranean salt formation and the theoretical pumping time for thetreatment fluid and the proposed cement slurry that has been manipulatedtheoretically permits formation of the proposed cement sheath with theproposed cement slurry that has been manipulated in the wellbore withoutsubstantial premature curing, and step (i), and repeating steps (b)-(i)until the theoretical pumping time experimentally permits formation ofthe proposed cement sheath in the wellbore with the proposed cementslurry that has been manipulated without substantial premature curing.

Element B2: Wherein step (j) comprises performing steps: (h)-(i) beforesteps: (f)-(g), and further comprising manipulating the proposed cementslurry after at least one of: step (h), and repeating steps (b)-(e) and(h) until the theoretical pumping pressure for the treatment fluid andthe proposed cement slurry that has been manipulated is theoreticallybetween the pore pressure and the fracture gradient of the subterraneansalt formation and the theoretical pumping time for the treatment fluidand the proposed cement slurry that has been manipulated theoreticallypermits formation of the proposed cement sheath with the proposed cementslurry that has been manipulated in the wellbore without substantialpremature curing, step (i), and repeating steps (b)-(e) and (h)-(i)until the theoretical pumping time experimentally permits formation ofthe proposed cement sheath in the wellbore with the proposed cementslurry that has been manipulated without substantial premature curing,step (f), and repeating steps (b)-(e), (h)-(i), and (f) until theproposed cement sheath based on the proposed cement slurry that has beenmanipulated is theoretically capable of withstanding the wellbore load,and step (g), and repeating steps (b)-(e), (h)-(i), and (f)-(g) untilthe proposed cement sheath based on the proposed cement slurry that hasbeen manipulated is experimentally capable of withstanding the wellboreload.

Element B3: Wherein the computational fluid dynamics model of step (h)is used to determine the theoretical pump time and pressure of thetreatment fluid and the proposed cement slurry based on: a flow rate ofthe treatment fluid, a flow rate of the proposed cement slurry, arheology of the treatment fluid, a rheology of the proposed cementslurry, a standoff profile, and the theoretical final wellbore radius.

Element B4: Wherein at least one of the flow rate of the treatment fluidand the flow rate of the cement slurry are manipulated and step (h) isrepeated.

Element B5: Wherein the rheology parameters of the treatment fluid andthe rheology parameters of the proposed cement slurry are selected fromthe group consisting of plastic viscosity, Bingham model yield point,Herschel-Bulkley model parameters, and any combination thereof.

Element B6: Wherein the theoretical thermal and thermo-mechanicalproperties of the proposed cement are calculated based on at least oneof thermal conductivity, thermal diffusivity, tensile strength,compressive strength, hydration volume change, Young's modulus, andPoisson's ratio.

Element B7: Wherein the salt creep analysis is based on secondary saltcreep; a combination of secondary salt creep and tertiary salt creep; ora combination of primary salt creep, secondary salt creep, and tertiarysalt creep.

Element B8: Wherein rheology parameters of the proposed cement slurryare used in step (c) to determine experimentally the rheology of theproposed cement slurry versus salt dissolution curve, and wherein therheology parameters are selected from the group consisting of plasticviscosity, Bingham model yield point, Herschel-Bulkley model parameters,and any combination thereof.

Element B9: Further comprising a wellhead with a tubular extendingtherefrom and into the wellbore, and a pump fluidly coupled to thetubular; and wherein step (m) is performed by introducing the finalcement slurry into the wellbore through the tubular.

By way of non-limiting example, exemplary combinations applicable toEmbodiment B include: B with B1 and B5; B with B1, B6, B7, and B9; Bwith B1, B3, and B8; B with B2, B4, B6, and B9; B with B2, B8, and B9; Bwith B6 and B7.

Therefore, the embodiments disclosed herein are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as they may be modified and practiced in different but equivalentmanners apparent to those skilled in the art having the benefit of theteachings herein. Furthermore, no limitations are intended to thedetails of construction or design herein shown, other than as describedin the claims below. It is therefore evident that the particularillustrative embodiments disclosed above may be altered, combined, ormodified and all such variations are considered within the scope andspirit of the present disclosure. The embodiments illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

The invention claimed is:
 1. A method comprising: (a) calculating atheoretical first wellbore radius for a wellbore in a subterranean saltformation having a treatment fluid therein based on salt creep analysisin the presence of formation-treatment fluid; (b) calculating atheoretical second wellbore radius in the subterranean salt formationduring a cementing operation with a proposed cement slurry based on saltcreep analysis in the presence of formation-cement slurry; (c)calculating a theoretical final wellbore radius in the subterranean saltformation based on the theoretical first wellbore radius, thetheoretical second wellbore radius, and salt dissolution expected aftera proposed cement sheath is theoretically formed; (d) calculatingtheoretically whether the proposed cement sheath is capable ofwithstanding a wellbore load by calculating theoretical thermal andthermo-mechanical properties of the proposed cement slurry based on saltcreep analysis in the presence of formation-cement sheath; (e)determining experimentally whether the proposed cement sheath is capableof withstanding the wellbore load based on actual thermal andthermo-mechanical properties of the proposed cement slurry after saltdissolution; (f) calculating theoretically a theoretical pump time and atheoretical pump pressure for the treatment fluid and the proposedcement slurry; (g) determining experimentally whether the theoreticalpumping time for the treatment fluid and the proposed cement slurry willpermit formation of the proposed cement sheath in the wellbore withoutsubstantial premature curing; (h) establishing a final cement slurry, afinal pumping pressure and time for the treatment fluid, and a finalpumping pressure and time for the final cement slurry; (i) performing awellbore operation with the treatment fluid using the final pumping timeand pressure for the treatment fluid; and (j) performing the cementingoperation with the final cement slurry using the final pumping time andpressure for the final cement slurry.
 2. The method of claim 1, furthercomprising manipulating the proposed cement slurry after at least oneof: step (d), and repeating steps (b)-(d) until the proposed cementsheath based on the proposed cement slurry that has been manipulated istheoretically capable of withstanding the wellbore load, step (e), andrepeating steps (b)-(e) until the proposed cement sheath based on theproposed cement slurry that has been manipulated is experimentallycapable of withstanding the wellbore load, step (f), and repeating steps(b)-(f) until the theoretical pumping pressure for the treatment fluidand the proposed cement slurry that has been manipulated istheoretically between a pore pressure and a fracture gradient of thesubterranean salt formation and the theoretical pumping time for thetreatment fluid and the proposed cement slurry that has been manipulatedtheoretically permits formation of the proposed cement sheath with theproposed cement slurry that has been manipulated in the wellbore withoutsubstantial premature curing, and step (g), and repeating steps (b)-(g)until the theoretical pumping time experimentally permits formation ofthe proposed cement sheath in the wellbore with the proposed cementslurry that has been manipulated without substantial premature curing.3. The method of claim 1, further comprising manipulating the proposedcement slurry after at least one of: step (f), and repeating steps(b)-(c) and (f) until the theoretical pumping pressure for the treatmentfluid and the proposed cement slurry that has been manipulated istheoretically between a pore pressure and a fracture gradient of thesubterranean salt formation and the theoretical pumping time for thetreatment fluid and the proposed cement slurry that has been manipulatedtheoretically permits formation of the proposed cement sheath with theproposed cement slurry that has been manipulated in the wellbore withoutsubstantial premature curing, step (g), and repeating steps (b)-(c) and(f)-(g) until the theoretical pumping time experimentally permitsformation of the proposed cement sheath in the wellbore with theproposed cement slurry that has been manipulated without substantialpremature curing, step (d), and repeating steps (b)-(c), (f)-(g), and(d) until the proposed cement sheath based on the proposed cement slurrythat has been manipulated is theoretically capable of withstanding thewellbore load, and step (e), and repeating steps (b)-(c), (f)-(g), and(d)-(e) until the proposed cement sheath based on the proposed cementslurry that has been manipulated is experimentally capable ofwithstanding the wellbore load.
 4. The method of claim 1, wherein step(f) comprises calculating theoretically the theoretical pump time andthe theoretical pump pressure for the treatment fluid and the proposedcement slurry based on a computational fluid dynamics model that is usedto determine the theoretical pumping time and pressure of the treatmentfluid and the proposed cement slurry based on: a flow rate of thetreatment fluid, a flow rate of the proposed cement slurry, rheologyparameters of the treatment fluid, rheology parameters of the proposedcement slurry, a standoff profile, and the theoretical final wellboreradius.
 5. The method of claim 4, wherein at least one of the flow rateof the treatment fluid and the flow rate of the cement slurry aremanipulated and step (f) is repeated.
 6. The method of claim 4, whereinthe rheology parameters of the treatment fluid and the rheologyparameters of the proposed cement slurry are selected from the groupconsisting of plastic viscosity, Bingham model yield point,Herschel-Bulkley model parameters, and any combination thereof.
 7. Themethod of claim 1, wherein the theoretical thermal and thermo-mechanicalproperties of the proposed cement slurry are calculated based on atleast one of thermal conductivity, thermal diffusivity, tensilestrength, compressive strength, hydration volume change, Young'smodulus, and Poisson's ratio.
 8. The method of claim 1, wherein the saltcreep analysis is based on secondary salt creep; a combination ofsecondary salt creep and tertiary salt creep; or a combination ofprimary salt creep, secondary salt creep, and tertiary salt creep. 9.The method of claim 1, further comprising using rheology parameters ofthe proposed cement slurry to determine experimentally a rheology of theproposed cement slurry versus salt dissolution curve, and wherein therheology parameters are selected from the group consisting of plasticviscosity, Bingham model yield point, Herschel-Bulkley model parameters,and any combination thereof.
 10. The method of claim 1, wherein step (j)is performed by introducing the final cement slurry into the wellborethrough a tubular extending from a wellhead and into the wellbore with apump fluidly coupled to the tubular.
 11. A system, comprising: acontainer containing a final cement slurry; a wellbore in a subterraneansalt formation; a wellhead; a line coupling the container to thewellhead; a tubular extending from the wellhead into the wellbore forconveying the final cement slurry into the wellbore, wherein the finalcement slurry, a final pumping pressure and time for a treatment fluid,and a final pumping pressure and time for the final cement slurry havebeen established by: (a) calculating a theoretical first wellbore radiusfor the wellbore having the treatment fluid therein based on salt creepanalysis in the presence of formation-treatment fluid; (b) calculating atheoretical second wellbore radius for the wellbore during a cementingoperation with a proposed cement slurry based on salt creep analysis inthe presence of formation-cement slurry; (c) calculating a theoreticalfinal wellbore radius in the subterranean salt formation based on thetheoretical first wellbore radius, the theoretical second wellboreradius, and salt dissolution expected after a proposed cement sheath istheoretically formed; (d) calculating theoretically whether the proposedcement sheath is capable of withstanding a wellbore load by calculatingtheoretical thermal and thermo-mechanical properties of the proposedcement slurry based on salt creep analysis in the presence offormation-cement sheath; (e) determining experimentally whether theproposed cement sheath is capable of withstanding the wellbore loadbased on actual thermal and thermo-mechanical properties of the proposedcement slurry after salt dissolution; (f) calculating theoretically atheoretical pump time and a theoretical pump pressure for the treatmentfluid and the proposed cement slurry; and (g) determining experimentallywhether the theoretical pumping time for the treatment fluid and theproposed cement slurry will permit formation of the proposed cementsheath in the wellbore without substantial premature curing; and a pumpconfigured to: (i) perform a wellbore operation with the treatment fluidusing the final pumping time and pressure for the treatment fluid; and(j) perform the cementing operation with the final cement slurry usingthe final pumping time and pressure for the final cement slurry.
 12. Thesystem of claim 11, wherein the final cement slurry has further beenestablished by manipulating the proposed cement slurry after at leastone of: step (d), and repeating steps (b)-(d) until the proposed cementsheath based on the proposed cement slurry that has been manipulated istheoretically capable of withstanding the wellbore load, step (e), andrepeating steps (b)-(e) until the proposed cement sheath based on theproposed cement slurry that has been manipulated is experimentallycapable of withstanding the wellbore load, step (f), and repeating steps(b)-(f) until the theoretical pumping pressure for the treatment fluidand the proposed cement slurry that has been manipulated istheoretically between a pore pressure and a fracture gradient of thesubterranean salt formation and the theoretical pumping time for thetreatment fluid and the proposed cement slurry that has been manipulatedtheoretically permits formation of the proposed cement sheath with theproposed cement slurry that has been manipulated in the wellbore withoutsubstantial premature curing, and step (g), and repeating steps (b)-(g)until the theoretical pumping time experimentally permits formation ofthe proposed cement sheath in the wellbore with the proposed cementslurry that has been manipulated without substantial premature curing.13. The system of claim 11, wherein the final cement slurry has furtherbeen established by manipulating the proposed cement slurry after atleast one of: step (f), and repeating steps (b)-(c) and (f) until thetheoretical pumping pressure for the treatment fluid and the proposedcement slurry that has been manipulated is theoretically between a porepressure and a fracture gradient of the subterranean salt formation andthe theoretical pumping time for the treatment fluid and the proposedcement slurry that has been manipulated theoretically permits formationof the proposed cement sheath with the proposed cement slurry that hasbeen manipulated in the wellbore without substantial premature curing,step (g), and repeating steps (b)-(c) and (f)-(g) until the theoreticalpumping time experimentally permits formation of the proposed cementsheath in the wellbore with the proposed cement slurry that has beenmanipulated without substantial premature curing, step (d), andrepeating steps (b)-(c), (f)-(g), and (d) until the proposed cementsheath based on the proposed cement slurry that has been manipulated istheoretically capable of withstanding the wellbore load, and step (e),and repeating steps (b)-(c), (f)-(g), and (d)-(e) until the proposedcement sheath based on the proposed cement slurry that has beenmanipulated is experimentally capable of withstanding the wellbore load.14. The system of claim 11, wherein step (f) comprises calculatingtheoretically the theoretical pump time and the theoretical pumppressure for the treatment fluid and the proposed cement slurry based ona computational fluid dynamics model that is used to determine thetheoretical pumping time and pressure of the treatment fluid and theproposed cement slurry based on: a flow rate of the treatment fluid, aflow rate of the proposed cement slurry, rheology parameters of thetreatment fluid, rheology parameters of the proposed cement slurry, astandoff profile, and the theoretical final wellbore radius.
 15. Thesystem of claim 14, wherein at least one of the flow rate of thetreatment fluid and the flow rate of the cement slurry are manipulatedand step (f) is repeated.
 16. The system of claim 14, wherein therheology parameters of the treatment fluid and the rheology parametersof the proposed cement slurry are selected from the group consisting ofplastic viscosity, Bingham model yield point, Herschel-Bulkley modelparameters, and any combination thereof.
 17. The system of claim 11,wherein the theoretical thermal and thermo-mechanical properties of theproposed cement slurry are calculated based on at least one of thermalconductivity, thermal diffusivity, tensile strength, compressivestrength, hydration volume change, Young's modulus, and Poisson's ratio.18. The system of claim 11, wherein the salt creep analysis is based onsecondary salt creep; a combination of secondary salt creep and tertiarysalt creep; or a combination of primary salt creep, secondary saltcreep, and tertiary salt creep.
 19. The system of claim 11, wherein thefinal cement slurry has further been established by using rheologyparameters of the proposed cement slurry to determine experimentally arheology of the proposed cement slurry versus salt dissolution curve,and wherein the rheology parameters are selected from the groupconsisting of plastic viscosity, Bingham model yield point,Herschel-Bulkley model parameters, and any combination thereof.
 20. Thesystem of claim 11, wherein step (j) is performed by introducing thefinal cement slurry into the wellbore through the tubular with the pump.